Method and apparatus for eliminating drill effect in pulse induction measurements

ABSTRACT

A method and apparatus provide a time-dependent calibration to essentially eliminate pipe effect in pulse-induction logging while drilling. Use of two receivers to provide calibration and measurement information allows determination of formation properties in a downhole environment while eliminating the effect of tool effects.

FIELD OF THE INVENTION

The invention concerns reduction of the drill effect on transientinduction measurements by use of a calibration technique.

BACKGROUND OF THE INVENTION

Use of pulse induction logging while drilling (“LWD”) resistivitymeasurements in downhole environments provides information aboutformations surrounding the borehole. Use of such techniques allows thecontinuation of drilling while acquiring information needed for drillsteering, or to determine proximity to formation interfaces, such asgas-oil, gas-water, or water-oil interfaces.

U.S. Pat. No. 7,167,006 (“the '006 patent”) to Itskovich, thespecification of which is incorporated herein by reference, describes anapparatus and method for a pulse induction LWD system using amulti-receiver array. Use of that invention provides improved resolutionof signals, allowing resolution of signals that would otherwise beunresolvable. This improved resolution is accomplished in that case byacquiring a calibration signal while the measurement tool is outside ofthe formation, and subtracting the calibration signal from themeasurement signal obtained while the tool is in the downholeenvironment.

While the calibration technique of the '006 patent provides improvedresolution, still further improvements in pulse induction LWDmeasurements are possible. Use of two receivers in the tool can allowtime-dependent calibration signals to be acquired from both receivers.These calibration signals can then be combined to create atime-dependent calibration coefficient. When pulse induction LWDmeasurements are taken downhole, the measurement signals received by thetwo receivers can be combined with the calibration coefficient togenerate a time-dependent differential measurement signal. This highresolution signal provides an improved ability to resolve interfaces inthe formation surrounding the borehole.

Accordingly, it is an object of the invention to provide improvedresolution of boundary locations in formations surrounding boreholes.

It is another object of the invention to provide measurements ofboundaries in formations for use in real-time geo-steering of drillingoperations.

It is yet another object of the invention to provide measurements todetermine the location of interfaces in a formation, such as gas-water,gas-oil, or water-oil interfaces.

SUMMARY OF THE INVENTION

The invention comprises a method and apparatus for substantiallyeliminating the drill effect in pulse induction LWD resistivitymeasurements. A multi-stage method comprises a first calibration stageand a second measurement stage. The apparatus used in performing thesemeasurements comprises a transmitter and two receivers. The receiversare longitudinally separated from the transmitter on the tool, and maybe placed on the same side of the transmitter or may be placed onopposite sides of the transmitter. In a preferred embodiment, thetransmitter and the receivers are mounted on a conductive section,covered with a ferrite shield.

Spacing between the receivers and the transmitter is primarily a matterof engineering choice. However, if the tool is to be used in ageo-steering application, it is important to avoid symmetrical placementof the receivers relative to the transmitter. In the event that theborehole runs parallel to a boundary, such as a water-oil boundary,symmetrical placement of the receivers relative to the transmitter couldresult in a zero-signal result using the calibration method of thisinvention.

In accordance with the invention, while outside of the formation, thetool is placed in the presence of a pipe and pulse inductionmeasurements are made by inducing a time-dependent current in thetransmitter. Time-dependent calibration signals are obtained andrecorded from each of the receivers. These calibration signals provideinformation reflecting the effects of the pipe at the receivers. Thecalibration phase thus provides time-dependent calibration signals C₁(t)and C₂(t). These signals can be recorded in a processor, such as acomputer.

Once the calibration information is recorded, the tool may be rundownhole to a position within a formation to be tested. Pulse inductionresistivity measurements can then be made, again by inducing atime-dependent current in the transmitter, and utilizing the same pulseheights and timing as with the calibration phase. The two receivers willthus produce time-dependent measurement responses S₁(t) and S₂(t).Providing these signals to the processor storing the calibrationinformation allows the resolution of a time-dependent differentialsignal ΔS(t)=S₂(t)−(S₁(t)·C₂(t)/C₁(t)). This differential signal issubstantially unaffected by the pipe and allows determination ofparameters of the surrounding formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of one embodiment of a tool of the presentinvention.

FIG. 2 is a graph depicting modeling results of a pulsed inductionmeasurement for a tool with a transmitter and a single receiver at aspacing of 0.5 meter.

FIG. 3 is a graph depicting modeling results of a pulsed inductionmeasurement for a tool with a transmitter and a single receiver at aspacing of 2 meters.

FIG. 4 is a graph depicting the results of applying the presentinvention by combining the results of the tests depicting in FIGS. 2 and3.

DETAILED DESCRIPTION

Referring to FIG. 1, a schematic representation of a tool of the presentinvention is shown. Tool 10 comprises a mandrel 12, preferably with aconductive body of a material such as ferrite. A transmitter 14 isspaced longitudinally away from a first receiver 16 and a secondreceiver 18. Transmitter 14 is electrically connected via connection 20to a processor, such as a computer, 22 which provides the current pulsesused in the LWD resistivity measurements. First receiver 16 and secondreceiver 18 are connected to processor 22 via connections 24 and 26,respectively. Processor 22 stores calibration information and processesreceived signals during pulsed induction measurements, and mayoptionally be used to control the steering of a drill bit. Those ofskill in the art will recognize that processor 22 may embody one or morecomputers, and may be controlled via a user interface or programmed forautomatic operation.

The spacing d between first receiver 16 and second receiver 18 is amatter of engineering preference, and these receivers may optionally beplaced on opposite sides of transmitter 14. However, as noted above, thereceivers should not be symmetrically placed about transmitter 14 in ageo-steering application, because application of the present inventionmay result in zero signal in this configuration if the boreholeparallels a water-oil boundary.

Referring to FIG. 2, modeling results are shown for a first receiver(such as first receiver 16 of FIG. 1) spaced at 0.5 meter from atransmitter (such as transmitter 14 of FIG. 1). The results are modeledfor a boundary between two layers of resistivities of 50 Ω·m and 2 Ω·m,respectively. The model includes a conductive pipe with resistance of0.714·10⁻⁶ Ω·m, and a ferrite nonconductive shield of length 1.5 m andμ=400. First calibration curve 210 reflects the signal from the pipealone in the absence of a formation. First measurement curve 212reflects the signal from the formation with a boundary spaced fourmeters from the tool. Second measurement curve 214 reflects the signalfrom the formation with a boundary spaced six meters from the tool.Third measurement curve 216 reflects the signal from the formation witha boundary spaced eight meters from the tool, and fourth measurementcurve 218 reflects the signal from the formation with a boundary spacedten meters from the tool. The second, third, and fourth measurementcurves are insufficiently resolved to provide meaningful information.

Similarly, referring to FIG. 3, measurement curves are modeled for thesame formation and pipe parameters as in FIG. 2, but with a secondreceiver (such as second receiver 18 of FIG. 1) spaced at 2 meters froma transmitter (such as transmitter 14 of FIG. 1). Second calibrationcurve 310 reflects the signal from the pipe alone in the absence of aformation. Fifth measurement curve 312 reflects the signal from theformation with a boundary spaced four meters from the tool. Sixthmeasurement curve 314 reflects the signal from the formation with aboundary spaced six meters from the tool. Seventh measurement curve 316reflects the signal from the formation with a boundary spaced eightmeters from the tool, and eighth measurement curve 318 reflects thesignal from the formation with a boundary spaced ten meters from thetool. Similarly to FIG. 2, the sixth, seventh, and eighth measurementcurves are insufficiently resolved to provide meaningful information.

However, application of the method of the present invention to the dataof FIGS. 2 and 3 provides a more meaningful result, as reflected in FIG.4. Four calculated curves 410, 412, 414, and 416 are depicted ascalculated for the boundary spacings of 4, 6, 8, and 10 meters,respectively. These curves are calculated by determining, for eachcurve,

ΔS(t)=S ₂(t)−(S ₁(t)·C ₂(t)/C ₁(t)).

For example, for the four meter boundary distance curve, S₁(t) isdepicted by first measurement curve 212 of FIG. 2, and S₂(t) is depictedby fifth measurement curve 312 of FIG. 3. For each of the four curves,C₁(t) is first calibration curve 210 of FIG. 2, and C₂(t) is depicted bysecond calibration curve 310 of FIG. 3. The time-dependent calibrationcoefficient C₂(t)/C₁(t) is shown in FIG. 4 as curve 418. As reflected inFIG. 4, application of the present invention to these curves producesadequate resolution to allow determination of boundary locations at eachof the 4, 6, 8, and 10 meter positions.

The above examples are included for demonstration purposes only and notas limitations on the scope of the invention. Other variations in theconstruction of the invention may be made without departing from thespirit of the invention, and those of skill in the art will recognizethat these descriptions are provide by way of example only.

1. A method of substantially eliminating drill effect on downhole pulseinduction resistivity measurements of a formation with a tool comprisinga transmitter, a first receiver, and a second receiver, comprisingtransmitting a time-dependent calibration signal via said transmitter,obtaining first and second time-dependent calibration responses fromsaid first receiver and said second receiver, respectively, combiningsaid first and second calibration responses to determine atime-dependent calibration coefficient, running said tool into adownhole environment, transmitting a time-dependent measurement signalvia said transmitter, obtaining first and second time-dependentmeasurement responses from said first receiver and said second receiver,combining said measurement responses with said calibration coefficientto produce a calibrated measurement value representing a quality of theformation, and determining a property of the formation from saidcalibrated measurement value.
 2. The method of claim 1, wherein the stepof combining said first and second calibration responses to determine atime-dependent calibration coefficient comprises determining thetime-dependent ratio of said first and second calibration responses. 3.The method of claim 1, wherein the step of combining said measurementresponses with said calibration coefficient to produce a calibratedmeasurement value comprises the step of determining the time-dependentproduct of said calibration coefficient and said second measurementresponse.
 4. The method of claim 3, wherein the step of combining saidmeasurement responses with said calibration coefficient to produce acalibrated measurement value comprises the step of subtracting theproduct of said calibration coefficient and said first measurementresponse from said second measurement response.
 5. The method of claim1, additionally comprising the step of placing said first and secondreceivers on said tool in the same longitudinal direction relative tosaid transmitter.
 6. The method of claim 1, additionally comprising thestep of placing said first and second receivers on said tool in opposinglongitudinal directions relative to said transmitter.
 7. The method ofclaim 1, additionally comprising the step of placing said first andsecond receivers on said tool asymmetrically relative to saidtransmitter.
 8. A method of substantially eliminating drill effect ondownhole pulse induction resistivity measurements of a formation arounda borehole, comprising providing a tool comprising a transmitter, afirst receiver, and a second receiver, placing said tool within a pipeoutside of the formation, sending a time-dependent signal via saidtransmitter, receiving a first calibration signal C₁(t) at said firstreceiver, receiving a second calibration signal C₂(t) at said secondreceiver, recording said first and second calibration signals, runningsaid tool into a downhole environment, sending a time-dependent signalvia said transmitter, receiving a first induction measurement signalS₁(t) at said first receiver, receiving a second induction measurementsignal S₂(t) at said second receiver, combining said first calibrationsignal, second calibration signal, first induction measure signal, andsecond induction measurement signal into a differential signal ΔS(t),whereinΔS(t)=S ₂(t)−(S ₁(t)·C ₂(t)/C ₁(t)), and determining a property of theformation from ΔS(t).
 9. The method of claim 8, additionally comprisingthe step of placing said first and second receivers on said tool in thesame longitudinal directions relative to said transmitter.
 10. Themethod of claim 8, additionally comprising the step of placing saidfirst and second receivers on said tool in opposing longitudinaldirections relative to said transmitter.
 11. The method of claim 8,additionally comprising the step of placing said first and secondreceivers on said tool asymmetrically relative to said transmitter. 12.An apparatus for determining a property of a formation surrounding aborehole while essentially eliminating drill effect in logging whiledrilling measurements, comprising, a tool comprising a transmitter, afirst receiver, and a second receiver, wherein said transmitter caninduce time-dependent currents in the formation, and a processor thatdetermines a property of the formation by combining a time-dependentcalibration function with time-dependent measurements received from saidfirst receiver and said second receiver, wherein said measurementsresult from currents induced in the formation by said transmitter. 13.The apparatus of claim 12, wherein said first receiver and said secondreceiver are attached to said tool in the same longitudinal directionrelative to said transmitter.
 14. The apparatus of claim 12, whereinsaid first receiver and said second receiver are attached to said toolin opposing longitudinal directions relative to said transmitter. 15.The apparatus of claim 12, wherein said first receiver and said secondreceiver are attached to said tool asymmetrically relative to saidtransmitter.
 16. The apparatus of claim 12, wherein said processordetermines said time-dependent calibration function from pulse inductionmeasurements taken with said tool in the presence of a pipe but outsideof the formation.
 17. The apparatus of claim 12, wherein said processordetermines said time-dependent calibration function by determining theratio of time-dependent calibration measurements from said firstreceiver and said second receiver.
 18. The apparatus of claim 12,wherein said processor determines a distance in the formation to one of(a) a gas-oil interface, (b) a water-oil interface, or (c) a gas-waterinterface.
 19. The apparatus of claim 12, wherein said processordetermines a distance to a bed boundary.
 20. The apparatus of claim 12,wherein said tool comprises a conductive body.